The analysis of gases from
petroleum products has been performed for decades using gas chromatography.
However, this technique was not applied specifically to transformer mineral
oil until the late 1960s/early 1970s and is now commonly called dissolved gas-in-oil
analysis (DGA). Some of the early developers of the technique were Dr. James
Morgan of Morgan Schaffer Systems, Canada, and researchers J.E. Dind, R. Daust
and J. Regis from the Canadian utility Hydro-Quebec.1

Because the technique was
so successful and provided a wealth of diagnostic information to detect incipient
faults, other laboratories such as Doble Engineering in Massachusetts began
utilizing the technique shortly thereafter. DGA has now become a standard in
the utility industry throughout the world and is considered to be the most important
oil test for insulating liquids in electrical apparatus. More importantly, an
oil sample can be taken at anytime from most equipment without having to take
it out of service, allowing a “window” inside the electrical apparatus that
helps with diagnosing and trouble-shooting potential problems.

Insulating fluid analysis
is performed using an array of physical, chemical and electrical tests. Physical
tests include analysis for interfacial tension, pour point, relative density,
viscosity, color and others. Tests such as water content, neutralization number,
oxidation inhibitor and polychlorinated biphenyls (PCBs) are considered chemical
tests. Electrical tests consist of analyses for dielectric breakdown voltage
and power factor. There are many other tests that can be performed but these
are the main ones executed on a routine basis. Most tests performed in North
America are based on ASTM test methods. In Europe and other parts of the world,
similar test methods come under the auspices of the International Electrotechnical
Committee TC10.

Because oil and solid insulation
degrade with service in electric apparatus, periodic sampling and testing are
necessary to ensure that deterioration is detected before it becomes excessive.
The rate at which the insulating materials degrade depends on several factors,
such as the type of oil preservation system (amount of oxygen present), operating
temperature, water content of the insulation, and the amounts and types of contaminants.
The frequency at which testing is conducted varies with the test, importance
of the equipment, whether an incipient-fault condition is known to be present
or a problem exists, and when a family of transformers has been identified as
having a history of problems.

The tests mentioned above
provide information on the oil quality itself but fail to provide in-depth diagnostic
information on the operating condition or health of the electric apparatus.
In addition, because most transformers in the United States are considered to
be sealed systems (equipped with preservation systems that retard the ingress
of moisture and oxygen), oil degradation can occur quite slowly over many years.
Many of the transformers in the United States that have been in-service for
more than 30 years still contain oil that is in good condition. There is one
test however, also performed on the insulating oil of the transformer, which
provides a means for diagnosing the operating condition of the electrical apparatus,
namely DGA.

Dissolved
Gas-in-Oil Analysis
Dissolved gas-in-oil analysis, performed in accordance with ASTM D3612 or IEC
60567, is by far the most frequently requested diagnostic test and the single
most important test performed on transformer oil. As the insulating materials
of an electrical apparatus, such as a transformer, break down from excessive
thermal or electrical stress, gaseous byproducts form. The byproducts are characteristic
of the type of incipient-fault condition, the materials involved and the severity
of the condition. Indeed, it is the ability to detect such a variety of problems
that makes this test such a powerful tool for detecting incipient-fault conditions
and for root-cause investigations after failures have occurred. Dissolved gases
are detectable in low concentrations (ppm level), which usually permit early
intervention before failure of the electrical apparatus occurs, and allow for
planned maintenance.

The
DGA technique involves extracting or stripping the gases from the oil and injecting
them into a gas chromatograph (GC). Detection of gas concentrations usually
involves the use of a flame ionization detector (FID) and a thermal conductivity
detector (TCD). Most systems also employ a methanizer, which converts any carbon
monoxide and carbon dioxide present into methane so that it can be burned and
detected on the FID, a very sensitive sensor.

Removing the gas from the
oil is one of the more difficult and critical portions of the procedure. The
original method, now ASTM D3612A, required that the oil be subjected to a high
vacuum in an elaborate glass-sealed system to remove most of the gas from the
oil. The gas was then collected and measured in a graduated tube by breaking
the vacuum with a mercury piston. The gas was removed from the graduated column
through a septum with a gas-tight syringe and immediately injected into a GC.
In the present modern day laboratory, however, mercury is not a favorite material
of chemists. For this reason, two additional extraction techniques have been
developed to eliminate mercury.

ASTM D3612B is called the
direct injection technique. In this method, the stripping of gases from the
oil and the gas analysis takes place inside the GC. Originally developed in
the mid-1980s for this application, the process involves injecting the oil into
a sample loop in the GC. When the GC run is initiated, the sample loop transfers
the oil through a series of valves into a stripper column. The stripper column
is composed of metal spheres in one end in which the oil overlays the surface
of the spheres to increase the surface area. Carrier gas is passed over the
spheres and extracts dissolved gases from the oil, which then pass through a
series of columns and on through the detectors. The oil is back-flushed and
purged from the system before the next sample is introduced.

The newest method, ASTM
D3612C, was approved about a year ago and is called the headspace method. Headspace
technology was used for DGA analysis for almost a decade. However, it was never
developed into a robust, reliable standard method until several years ago when
Jocelyn Jalbert of Hydro-Quebec developed a headspace method using a Hewlett
Packard (now Agilent Technologies) instrument.2 The technique involves injecting
an exact volume of oil into a purged and pressurized headspace vial. The gas
in the oil is then allowed to develop an equilibrium with the vial headspace
under shaking and heating conditions. After a predetermined sample extraction
time, the autosampler removes a portion of the gas from the vial headspace and
injects it into the GC. The advantage of this method is that it can be automated
and reduces the risk of operator error from excessive handling of the sample
during preparation and injection.

Of course, each method has
its advantages and disadvantages. Method A (ASTM D3612A) is by far the longest-standing
technique and is still widely used today and offers accurate, reliable sample
preparation if followed rigorously. However, the alternative methods, which
are more easily automated, are gaining acceptance as they are shown to be reliable.
None of the extraction techniques completely removes all the gases from the
oil. This is due to the solubility coefficient of each gas, which must be accounted
for in the final concentration determination. Laboratories must also work with
commercial suppliers to develop gas and gas-in-oil standards or they must prepare
standards themselves, because these are not currently available from national
standardization bodies such as the NIST. Repeatability and accuracy are also
of the utmost importance as small changes, even several ppm in some cases, can
mean the difference between an active incipient fault condition that requires
immediate attention or one that is stable and requires no attention.

Just like with industrial
oil analysis, good sampling practice is important for obtaining accurate DGA
data. Key gases such as hydrogen and carbon monoxide could easily be lost from
a sample because of their low solubilities in oil. In order to minimize the
loss of gases, ASTM D3613 requires samples to be taken using gas-tight glass
syringes or metal bulbs; these are available from several suppliers or from
commercial transformer oil analysis labs.

Additionally, oxygen and
nitrogen are always present, their concentrations vary with the type of preservation
system used on the transformer. Also, gases such as propane, butane, butene
and others can be formed as well, but their use for diagnostic purposes is not
widespread. The concentration of the different gases provides information about
the type of incipient-fault condition present as well as the severity. For example,
four broad categories of fault conditions have been described and characterized
in Table 13.

Electrical discharges or
inadequate cooling of the paper insulation cause it to overheat, generating
carbon oxide gases. Examination of the relative composition or ratios of gases
present can provide further refinement of the diagnosis. This typically involves
using either Rogers ratio or Dornenberg ratios.

The severity of an incipient-fault
condition is ascertained by the total amount of combustible gases present (CO,
H2, C2H2, C2H4, C2H6,
CH4) and their rate of generation. Generally, transformers will retain
a large portion of the gases generated and therefore produce a cumulative history
of the insulating materials’ degradation. This is an important tool for detecting
and trending incipient problems. However, it also means that care is needed
in interpreting values for a first-time analysis on service-aged transformers
(more than several years old), which could contain residual gases from previous
events.

Some gas generation is expected
from normal aging of the transformer insulation. Therefore it is important to
differentiate between normal and excessive gassing rates. Normal aging or gas
generation varies with transformer design, loading and type of insulating materials.
Routinely, general gassing rates for all transformers are used to define abnormal
behavior. Specific information for a family of transformers can be used when
sufficient dissolved gas-in-oil data are available.

Acetylene is considered
to be the most significant gas generated. An enormous amount of energy is required
to produce acetylene, which is formed from the breakdown of oil at temperatures
in excess of 700°C. Excessively high overheating of the oil will produce the
gas in low concentrations; however, higher concentrations are typically symptomatic
of sustained arcing, a more serious operational issue that can cause a transformer
failure if left unchecked.

DGA is used not only as
a diagnostic tool but also to stem apparatus failure. Failure of a large power
transformer not only results in the loss of very expensive equipment (costs
can exceed one million U.S. dollars) but it can cause significant collateral
damage as well. Revenue losses due to customers’ outages may be the least worrisome
consequence of a failure. Replacement of that transformer can take up to a year
if the failure is not catastrophic and can result in tremendous revenue losses
and fines. If the failure is catastrophic, then additional loses could be realized,
such as adjacent transformers, environmental problems from the release of oil,
which could be as much as 20,000 gallons, and the resulting fire that must be
contained and smothered, all of which are a utility’s worst nightmare. In order
to avoid such a failure, the sample frequency of most large power transformers
is between one and three years. However, sampling frequencies will increase
as an incipient fault is detected and monitored. Often times sampling frequencies
are dictated by insurance requirements, which often stipulate that annual transformer
oil analysis must be conducted to ensure continued coverage.

The following examples are
extreme but serve to illustrate how the dissolved gas-in-oil test can be used
to highlight active problems.

EXAMPLE
14
The utility suspected that the magnetic shunt pads attached to the inside of
this transformer tank had come loose and were either touching the core (layered
steel structure around which the copper winding is installed) or were coming
very close. The result was intermittent unintentional core grounding and stray
flux causing localized overheating of the oil.

EXAMPLE
25
It was suspected that a single line to ground through-fault caused the failure
of this transformer. The fault was of enough energy to destroy one of the windings.
Acetylene was a predominant gas possibly indicating that arcing may have occurred.
The acetyleneto-ethylene ratio indicated the problem could be either high temperature
overheating of the oil, arcing or both. The problem was likely in the winding
because it involved cellulosic materials, as witnessed by the comparatively
high carbon monoxide and carbon dioxide concentrations.

EXAMPLE
35
A technician noticed that this transformer was enveloped in a cloud of steam
during a rainstorm. This prompted an investigation where it was found that the
temperature indicator pegged. It was estimated that the temperature in the unit
had been greater than 200°C. It was discovered also that the unit became highly
overloaded during some switching functions due to current imbalances in the
three phases. The condition probably existed on and off for two years. An internal
investigation found the cellulosic paper used as an insulant was brittle and
crumbly. Again, the key gas indicators for this condition were carbon monoxide
and carbon dioxide.

Oil testing is an important
part of a utility’s electric apparatus condition assessment. As these cases
illustrate, dissolved gas-in-oil analysis is the most important diagnostic test
for detecting a wide range of problems.

Griffin, P.J., (1998).
Criteria for the Interpretation of Data for Dissolved Gases in Oil from Transformers
(A Review). ASTM Special Technical Publication 998.

Lewand, L.R. and Griffin,
P.J., (2000). The Effective Use of Laboratory Analysis of Insulating Oil as
a Maintenance Tool. Proceedings of the Sixty-Seventh Annual International
Conference of Doble Clients. Sec. 5-8.

Griffin, P. J. and Lewand,
L.R., (1995). A Practical Guide for Evaluating the Condition of Cellulosic
Insulation in Transformers. Proceedings of the Sixty-Second Annual International
Conference of Doble Clients. Sec. 5-6.